Several controlled pressure drilling techniques are used to drill wellbores. In general, controlled pressure drilling includes managed pressure drilling (MPD), underbalanced drilling (UBD), and air drilling (AD) operations.
In the Managed Pressure Drilling (MPD) technique, a MPD system uses a closed and pressurizable mud-return system, a rotating control device (RCD), and a choke manifold to control the wellbore pressure during drilling. The various MPD techniques used in the industry allow operators to drill successfully in conditions where conventional technology simply will not work by allowing operators to manage the pressure in a controlled fashion during drilling.
During drilling, the bit drills through a formation, and pores become exposed and opened. As a result, formation fluids (i.e., gas) can mix with the drilling mud. The drilling system then pumps this gas, drilling mud, and the formation cuttings back to the surface. As the gas rises up the borehole, the pressure drops, meaning more gas from the formation may be able to enter the wellbore. If the hydrostatic pressure is less than the formation pressure, then even more gas can enter the wellbore.
FIG. 1A schematically shows a controlled pressure drilling system 10 according to the prior art. As shown here, this system 10 is a Managed Pressure Drilling (MPD) system having a rotating control device (RCD) 12 from which a drill string and drill bit (not shown) extend downhole in a wellbore through a formation. The rotating control device 12 can include any suitable pressure containment device that keeps the wellbore closed at all time while the wellbore is being drilled. The system 10 also includes mud pumps (not shown), a standpipe (not shown), a mud tank (not shown), a mud gas separator 18, and various flow lines (14, 16, etc.), as well as other conventional components. In addition to these, the MPD system 10 includes an automated choke manifold 20 that is incorporated into the other components of the system 10.
One suitable example of a drilling system 10 with a choke manifold 20 is the Secure Drilling™ System available from Weatherford. Details related to such a system are disclosed in U.S. Pat. No. 7,044,237, which is incorporated herein by reference in its entirety.
The automated choke manifold 20 manages pressure during drilling and is incorporated into the system 10 downstream from the rotating control device 12 and upstream from the gas separator 18. The manifold 20 has chokes 22A-B, choke actuators 24A-B, a mass flow meter 26, pressure sensors, a hydraulic power unit 50 to actuate the chokes 22A-B, and a controller 40 to control operation of the manifold 20.
The system 10 uses the rotating control device 12 to keep the well closed to atmospheric conditions. Fluid leaving the well flows through the automated choke manifold 20, which measures return flow and density using the flow meter 26 installed in line with the chokes 22A-B. Software components of the manifold 20 then compare the flow rate in and out of the wellbore, the injection pressure (or standpipe pressure), the surface backpressure (measured upstream from the drilling chokes 22), the position of the chokes 22A-B, and the mud density. Comparing these variables, the system 10 identifies minute downhole influxes and losses on a real-time basis and to manage the annulus pressure during drilling. All of the monitored information can be displayed for the operator at the controller 40.
During drilling operations, the controller 40 monitors for any deviations in values and alerts the operators of any problems that might be caused by a fluid influx into the wellbore from the formation or a loss of drilling mud into the formation. In addition, the controller 40 can automatically detect, control, and circulate out such influxes by operating the chokes 22A-B on the choke manifold 20 with the power unit 50.
For example, a possible fluid influx can be noted when the “flow out” value (measured from flow meter 26) deviates from the “flow in” value (measured from the mud pumps). When an influx is detected, an alert notifies the operator to apply the brake until it is confirmed safe to drill. Meanwhile, no change in the mud pump rate is needed at this stage.
In a form of auto kick control, however, the controller 40 automatically closes the choke 22A-B to a determined degree to increase surface backpressure in the wellbore annulus and stop the influx. Next, the controller 40 circulates the influx out of the well by automatically adjusting the surface backpressure, thereby increasing the downhole circulating pressure and avoiding a secondary influx.
On the other hand, a possible fluid loss can be noted when the “flow in” value (measured from the pumps) is greater than the “flow out” value (measured by the flow meter 26). Similar steps as those above but suited for fluid loss can then be implemented by the controller 40 to manage the pressure during drilling in this situation.
When the managed pressure drilling system 10 is deployed on a drilling rig floor, hydraulic power is typically supplied remotely to the chokes 22A-B of the system 10. As shown in FIG. 1B, a hydraulic power unit 50 includes a hydraulic reservoir 52, one or more hydraulic pumps 54, one or more accumulators 56, hydraulic choke control valves 58A-B, and necessary piping, fittings, and valves. Each choke 22A-B located in the choke unit 20 has its actuator 24A-B connected by flow paths 55A-B to one of the hydraulic choke control valves 58A-B located in hydraulic power unit 50.
As will be appreciated, the flow-paths 55A-B for the hydraulic power used to control the chokes 22A-B may need to travel some distance (e.g., 12 ft. or so). Additionally, the flow paths 55A-B can be coupled with various bends, not necessarily depicted in this schematic view. Further, wave pulses may tend to originate from the pump(s) 54 and travel along the flow paths 55A-B.
Moreover, any hydraulic hoses used for the flow-paths 55A-B can elastically expand (i.e., expand diametrically) as the hydraulic pressure increases. Conversely, the hydraulic hoses used for the flow-paths 55A-B can elastically contract (i.e., contract diametrically) as the hydraulic pressure decreases. When the length of the hoses for the flow-paths 55A-B is long, a large volume of fluid can be contained in the hoses, thereby causing measurable increases and decreases in hydraulic fluid volume corresponding to these pressure changes. As a result, the hoses for the flow-paths 55A-B can effectively respond as an accumulator and can further exaggerate or reduce the responsiveness of the choke actuators.
Consequently, the distance, bends, wave pulses, and the like can create hydraulic frictional losses and delays that hinder the response of the chokes 22A-B during operations. Moreover, when managed pressure drilling uses two or more chokes 22A-B in simultaneous operation, the hydraulic losses in the flow-path 55A can be different from the hydraulic losses in flow-path 55B depending on construction of the materials or differences in geometries. This can lead to a different system response between the chokes 22A-B, which requires a more complex control algorithm for the controller 40. For example, one hydraulic choke 22A may tend to respond more slowly than the other choke 22B.
It is recognized that electric actuation of the chokes 22A-B may have faster response times (i.e., closing and opening times for the chokes 22A-B) when compared to hydraulic actuation. However, electric actuation on the drilling rig may not be desirable or even possible for various reasons so that hydraulic actuation may be preferred.
What is needed is a way to mitigate any timing differences that may occur when multiple hydraulic chokes are operating simultaneously, as well as improve the response of individual chokes in a choke manifold for a drilling system. Therefore, the subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.